Typically, a liquid called drilling mud is used to drill well bores. Under certain conditions, a pneumatic fluid, such as air, may be used instead of drilling mud to drill well bores. At first, drilling with a pneumatic fluid initially appears to be less complicated than drilling with a liquid drilling mud. Drilling mud, however, is relatively incompressible when compared to the compressible gases of a pneumatic fluid. Where a particular volume of drilling mud at the surface will effectively have the same volume and other properties at depth, a pneumatic fluid will have a volume that is dependent on pressure, temperature, and flow rate. Conceptual estimates of the action of drilling mud during drilling do not apply when a pneumatic fluid is used. Many drillers in the field either do not fully appreciate these differences, or are not fully able to adapt to these differences in their drilling procedures. Thus, many of the drilling procedures and standards-of-practice used for drilling with drilling-mud are loosely adapted and used when drilling with pneumatic fluid.
Owing to the compressibility of pneumatic fluid, a great amount of control of distribution of energy, pressures, and lift may be obtained in a well bore. The complexity, and the incorrect application of drilling-mud techniques to pneumatic drilling, has generally prevented the industry from taking advantage of this additional level of control provided by pneumatic drilling.
One of the problems of drilling with pneumatic fluid is that all of the pneumatic fluid flows down the drill string, through the drill bit, and up the well bore. Frictional losses are significant. Also, there is no control of the velocity of the pneumatic fluid along the well bore, as changes in the well bore volume will directly affect the compression of the pneumatic fluid. Approximately ten years ago, tools were introduced to the Arkoma Basin which diverted some of the pneumatic fluid out of the drill string into the well bore at various locations, such that not all pneumatic fluid flowed through the drill bit. This short-cut path of pneumatic flow brought several theoretical advantages. First, additional lift was provided in the well bore at the point of diversion. Since this pneumatic fluid did not experience the frictional losses of traveling down to the drill bit and back up to the point of diversion, more energy could be available from the pneumatic fluid to provide lift in the well bore. Second, excess pneumatic fluid flow at the bit can cause excessive erosion of the well bore. Diverting this excess pneumatic fluid flow prior to reaching the bit could decrease damage to the well bore. The diverter could also help dislodge blockages in the well bore, by providing additional lift underneath the blockage. A diverter could also be useful when using a flat bottom bit. Such a bit usually has a percussion or hammer tool connected to the top of the bit. Only a small amount of set-down weight is necessary to operate the hammer tool, which generally reduces well bore drift. A diverter, in theory, helps reduce the amount of pneumatic fluid reaching the hammer tool to the optimal amount needed to drill without waste or hole damage. Unfortunately, many of these promised advantages met with limited success, owing to limitations of the diverters and their method of application.
The significance of the technology and how it could impact air-drilled holes was not fully understood. Setting depths, nozzle sizes and air volumes were not precisely calculated. Without a computer model to augment the diverter tool, it was impractical to select the optimum volume of air to divert, locate where to place the diverter tool, select what nozzle size to use for the valves, and estimate savings from the reduced down hole friction. Many of the promised advantages of using a diverter tool were not realized. The complexities of modeling a compressible pneumatic drilling fluid over a relatively incompressible drilling-mud limited the usefulness of diverter technology.
Therefore, the diverter tool was almost exclusively used to increase penetration rates and stay-on-air while producing large amounts of water. It was very successful in this application. As an example, in West Texas the diverter tools were used to drill at rates of more than one hundred feet per hour, producing 600 barrels of water per hour with a hammer tool and flat bottom bit. Previously, this was not possible without a diverter.
The diverter tools used in the past typically required more pneumatic flow over standard drilling. Hence, little energy savings was realized. Required opening and closing pressure differentials were generally high. These diverter tools operated in a normally closed position, meaning that no pneumatic flow was diverted unless a substantial pressure differential existed between the pneumatic flow in the drill pipe and the well bore. Valve operation of the diverter was completely controlled by the drill pipe and well bore pressure differential. Hence, these diverter valves typically fluttered, causing an unpredictable and erratic amount of diversion. As the pressure in the well bore increased, more pneumatic pressure would have to be pumped into the drill pipe to keep the velocities high enough to balance the higher pressures and keep the valve open. The diverter tool could not be used to selectively control the lift gradient in the well bore, due to its normally closed position and inability to be independently opened by the drill pipe pressure alone.